Enhancing acid fracture conductivity

ABSTRACT

Methods and systems for enhancing acid fracture conductivity of acid fracture treatments on subterranean formations are provided. An example method of acid fracture treatment includes initiating fracturing of a subterranean formation in which a wellbore is formed to create a formation fracture, after initiating the fracturing for a period of time, injecting an acidic fluid into the wellbore to etch walls of the formation fracture to thereby create fracture conductivity, introducing a gas into the wellbore to foam fluids in the wellbore, and increasing a foam quality of the fluids with time during the treatment. The foam quality is based on a volume of the introduced gas and a total volume of the fluids in the wellbore.

CROSS-REFERENCE TO RELATED APPLICATION(S)

This application is a continuation application of and claims the benefitof priority to U.S. patent application Ser. No. 15/595,108, filed on May15, 2017, the contents of which are hereby incorporated by reference.

TECHNICAL FIELD

This specification relates to fracturing methods for subterraneanformations, particularly to acid fracture treatments.

BACKGROUND

Various methods including proppant fracturing and acid fracturing can beused to fracture a subterranean formation to increase gross permeabilityor conductivity and enhance production of fluids therefrom. In proppantfracturing, a propping agent is used to keep a fracture open after afracturing treatment. In acid fracturing, acid is used to etch channelsin a formation rock that forms walls of a fracture, and the rock can bepartially soluble in the acid so that the channels can be etched in thefractured walls.

SUMMARY

The present specification describes methods and systems for enhancingacid fracture conductivity of acid fracture treatments on subterraneanformations.

One aspect of the present disclosure features a method of acid fracturetreatment, including: initiating fracturing of a subterranean formationin which a wellbore is formed to create a formation fracture; afterinitiating the fracturing for a period of time, injecting an acidicfluid into the wellbore to etch walls of the formation fracture tothereby create fracture conductivity; introducing a gas into thewellbore to foam fluids in the wellbore; and increasing a foam qualityof the fluids with time during the treatment, wherein the foam qualityis based on a volume of the introduced gas and a volume of the fluids inthe wellbore.

In some implementations, the method further includes: monitoringreaction of the fracture to the acidic fluid during the treatment; andcontrolling the increasing of the foam quality based on the monitoredreaction by adjusting at least one of an injection rate of the acidicfluid, an injection volume of the acidic fluid, an introduction rate ofthe gas, or an introduction volume of the gas. In some cases, monitoringreaction of the fracture can include monitoring at least one ofparameters including a treating pressure, a wellhead pressure, abottomhole pressure, a fluid pumping rate, a gas pumping rate, and aslurry rate; and determining the reaction of the fracture based on themonitored parameters.

In some implementations, the method further includes: calculating thefoam quality based on the volume of the introduced gas and the volume ofthe fluids in the wellbore; and correcting the calculated foam qualitywith at least one of a calculated wellhead foam quality, a predictedbottomhole foam quality, or a calculated actual bottomhole foam quality.The method can further include: calculating the calculated wellhead foamquality based on an actual wellhead pressure and a temperature;predicting the predicted bottomhole foam quality based on a predictedbottomhole internal phase; and calculating the calculated actualbottomhole foam quality based on a calculated bottomhole internal phasethat is calculated based on a bottomhole pressure and the temperature.

The method can further include determining that a dimension of thecreated formation fracture reaches a value, and in response, injectingthe acidic fluid into the wellbore. Introducing the gas can includeintroducing the gas after the creation of the formation fracture anduntil completion of the treatment. Introducing a gas into the wellborecan include generating the gas in-situ in the fluids in the wellbore.The method can further include decreasing an injection rate of theacidic fluid with time during the treatment.

In some implementations, injecting the acidic fluid includes injectingthe acidic fluid at a pressure lower than a fracture closure pressurethat is capable of causing a closure of the formation fracture. In somecases, injecting the acidic fluid includes keeping an injection rate ofthe acidic fluid constant with time during the treatment. In some cases,injecting the acidic fluid includes increasing an injection rate of theacidic fluid with time during the treatment.

In some implementations, initiating the fracturing includes flowing afracturing pad fluid into the wellbore to break down the formation tothereby create the formation fracture. The method can includealternately performing steps of injecting the fracturing pad fluid andthe acidic fluid, while keeping introducing the gas during the steps. Insome cases, a volume of the introduced gas for a current step is nosmaller than a volume of the introduced gas for a previous step. In somecases, a volume of the introduced gas for a current step is smaller thana volume of the introduced gas for a previous step. In some cases, aninjection rate of the introduced gas for a current step is no smallerthan an injection rate of the introduced gas for a previous step. Thefracturing pad fluid can include at least one of a gelled water or acrosslinked gel fluid.

In some examples, the acidic fluid is configured to dissolve theformation and can includes at least one of: hydrochloric (HCl) acid witha concentration from 0.1 to 32 wt. %, formic acid with a concentrationfrom 0.1 to 12 wt. %, acetic acid with a concentration from 0.1 to 20wt. %, methaneseleninic (MSA) acid with a concentration from 0.1 to 92wt. %, chelating agent with a concentration from 0.1 to 40 wt. %, or acarboxylic acid system. The acidic fluid can be configured to be gelledby linearly polymers, gelled by crosslinked polymer system, gelled byviscoelastic surfactant (VES) system, emulsified by diesel or oil, orfoamed by a particular gas.

In some examples, the introduced gas has low density and low viscosityand includes at least one of: nitrogen (N2), carbon dioxide (CO2), air,methane, or natural gas. The method can further include adding adiversion fluid to the acidic fluid, and the diversion fluid can includeat least one of a crosslinking polymer, a surfactant based material, ora crosslinked non-reactive fluid. The method can further includecleaning the wellbore after closure of the formation fracture.

Another aspect of the present disclosure features a method of acidfracture treatment, including: initiating fracturing of a subterraneanformation in which a wellbore is formed to create a formation fracture;after initiating the fracturing for a period of time, injecting anacidic fluid into the wellbore to etch walls of the formation fractureto thereby create fracture conductivity; introducing into the wellborean acidic retard system configured to reduce reactivity of the acidicfluid in the wellbore; monitoring reaction of the fracture to the acidicfluid and the acidic retard system during the treatment; and controllinga foam quality of fluids in the wellbore based on the monitoredreaction, wherein the foam quality is based on the introduced acidicretard system.

Controlling a foam quality of fluids in the wellbore can includeincreasing the foam quality with time during the treatment. In somecases, controlling a foam quality of fluids in the wellbore includesadjusting at least one of an injection rate of the acidic fluid, aninjection volume of the acidic fluid, an introduction rate of the acidicretard system, an introduction volume of the acidic retard system, or anintroduction concentration of an acidic retard agent in the acidicretard system. The acidic retard system can include an acidic retardagent that includes at least one of: a gas with low density and lowviscosity, linearly polymer, crosslinked polymer system, viscoelasticsurfactant (VES) system, or diesel or oil.

The details of one or more implementations of the subject matter of thisspecification are set forth in the accompanying drawings and associateddescription. Other features, aspects, and advantages of the subjectmatter will become apparent from the description, the drawings, and theclaims.

DESCRIPTION OF DRAWINGS

FIG. 1 is a schematic diagram illustrating a sectional view of aformation penetrated with a wellbore in an acid fracture treatment.

FIG. 2 is a flowchart of an example process of an acid fracturetreatment with gas foaming.

FIG. 3 is a flowchart of another example process of an acid fracturetreatment with an acidic retardation system.

FIG. 4A shows an example time diagram of an acid fracture treatmentwithout gas foaming.

FIG. 4B shows an example time diagram of an acid fracture treatment withgas foaming.

DETAILED DESCRIPTION

FIG. 1 is a schematic diagram illustrating a sectional view 100 of asubterranean formation 102 penetrated with a wellbore 106 in an acidfracture treatment (or acid fracturing). The formation 102 can be acarbonate-containing formation. The wellbore 106 can includeperforations 108 that extends into the formation 102. Fluids 120 can beinjected (or pumped) into the wellbore 106 and flowed into the formation102 through the perforations 108.

In the acid fracture treatment, a fracturing pad fluid can first beinjected into the wellbore 106 to break down the formation 102 tothereby create one or more formation fractures 104. Then, an acidicfluid can be injected into the wellbore 106 to etch walls of thefracture 104, for example, surfaces of a formation rock, to createfracture conductivity, for example, to create conducive paths 112,between fracture portions 110 of the fractures 104. The rock can includecalcite, limestone or dolomite. In some implementations, gases 130 suchas Nitrogen (N₂) can be also introduced (pumped or generated in situ)into the wellbore 106 to foam the fluids in the wellbore 106 during theacid fracture treatment.

The success of an acid fracture treatment may depend on the createdfracture conductivity being retained under a fracture closure pressure(or stress). Fracture conductivity can be a competition between twophenomena: etching of a rock surface in a formation and weakening of arock strength by the acid. Under the fracture closure pressure, inaddition to uneven etching, fracture conductivity can depend on theability of asperities (or harshness) of the rock to maintain mechanicalintegrity. The final conductivity of the fracture depends on factorsthat create the conductive path and those maintaining the fracture openunder the fracture closure pressure.

A first step of an acid fracture treatment is to create a conductivepath in a rock of a formation, where a number of parameters can be used,including acid concentration, soaking time, different acid systems, andadditives. A second step of the acid fracture treatment is to keep theconductive path open, which can depend on the remaining hardness ofasperities of the rock. As hardness of the asperities increase, theconductivity will be maintained. Therefore, it is desirable to optimizeparameters to maintain the hardness of the rock.

Acid can be gelled, crosslinked, or emulsified to maintain fracturewidth and minimize fluid leakoff, and acid fracturing can be applied inshallow, low-temperature carbonate reservoirs, in which a reservoirtemperature can be less than 200° F. and a maximum effective stress onthe fracture can be less than 5,000 psi. Low temperature reduces areaction rate between the acid and the formation, which allows the acidto penetrate deeper into the fracture before becoming consumed. Forexample, limestone reservoirs are ductile, and a low effective stress onthe fracture is required to maintain adequate fracture conductivity overthe life of the well. In deep limestone reservoirs, high bottom-holetemperature and high effective stress are applied on the fracture, whichmakes it hard to stimulate the formation.

FIG. 2 shows an example process 200 of an acid fracture treatment withgas foaming, where a gas is injected into liquids in a wellbore to formfoams. A foam is a dispersion of gas in a liquid, which can bestabilized by inclusion of a surfactant foaming agent. The liquid can bewater, acid, hydrocarbon such as diesel, or a mixture ofwater/hydrocarbon or acid/hydrocarbon. The gas, or internal phase, canbe any gas available. In some cases, the gas has low density and lowviscosity, for example, nitrogen (N₂), carbon dioxide (CO₂), air,methane, or natural gas. The foams can be homogenous mixtures within arange of bubble sizes, for example, under 200 microns. Interactionbetween bubbles can be structured (or configured) to create a foam witha high quality, for example, with a foam quality above 53%. The foamscan be stable for a period of time, for example, several hours. Thefoams can offer various advantages, for example, high sand carrying andsuspension capacity, low filtration loss, low hydrostatic pressure, lowpressure drop by friction, fast fluid recovery, low formation damage,and absence of fracture conductivity reduction due to fluid ingredients.Thus, the acid fracture treatment with gas foaming enables to enhanceconductivity of an acid fractured wellbore, for example, in a hightemperature—high stress-depleted carbonate formation.

Fracturing of a subterranean formation is initiated to create aformation fracture (202). A wellbore can be formed in the formation. Theformation, the fracture, and the wellbore can be the formation 102, thefracture 104, and the wellbore 106 of FIG. 1, respectively.

In some cases, initiating the fracturing can include cooling down thewellbore, for example, with treated water, and then injecting an initialfracturing fluid to provide initial penetration into the formationduring a spearhead step. The treated water can be water mixed withsurfactant and clay control agent. In some cases, the treated water caninclude completion fluid and Brines. The initial fracturing fluid caninclude an acid with a relatively low viscosity, for example, 26%hydrochloric acid (HCl).

After the spearhead step, a fracturing pad fluid can be injected intothe wellbore to break down the formation to thereby create the formationfracture. The fracturing pad fluid can include no acid. In someexamples, the fracturing pad fluid is a water-based pad, for example, agelled water or a crosslinked gel fluid. The fracturing pad fluid caninclude delayed borate, zirconium, or titanium xlinked fluid system.

After initiating the fracturing for a period of time, an acidic fluid isinjected into the wellbore to etch walls of the formation fracture tothereby create fracture conductivity (204).

In some implementations, the process 200 includes determining that adimension of the created formation fracture reaches a value, and inresponse, injecting the acidic fluid into the wellbore. In someexamples, the dimension of the formation fracture can be measured ordetermined by distributed temperature survey, for example, using fiberoptic with resistivity measurements in real time coupled with a fracturepressure matching. In some examples, a seismic and mathematical modelcan be used to predict fracture dimension. The pad fluid can be pumpedinto the wellbore to create the fracture with a desired height, width,length, or any suitable combination therefrom. In a particular example,the created fracture has a volume that is around 10-20% of a totalpumped volume of the pad fluid.

The acidic fluid can include any fluid capable of etching or dissolvingrocks, for example, an acid fluid. The acidic fluid can be gelled,crosslinked, or emulsified to maintain the fracture width, to minimizefluid leakoff and to have a good retardation for deep acid penetration.

In some examples, hydrochloric acid (HCl) at a concentration range of15-28 wt.% is used to obtain deep acid penetration and large etching. Insome cases, formic acid (HCOOH) or acetic acid (CH₃COOH) is used for ahigher temperature application when HCl is not recommended for usebecause of its fast reactivity and high corrosively at high temperature.In a particular example, the acid fluid includes high temperatureemulsified acid system with an acid concentration of 28.0 wt. %.

In some examples, the acidic fluid includes at least one of:hydrochloric (HCl) acid with a concentration from 0.1 to 32 wt. %,formic acid with a concentration from 0.1 to 12 wt. %, acetic acid witha concentration from 0.1 to 20 wt. %, methaneseleninic (MSA) acid with aconcentration from 0.1 to 92 wt. %, chelating agent with a concentrationfrom 0.1 to 40 wt. %, or a carboxylic acid system. The chelating agentcan include L-glutamic acid-N, N-diacetic acid (GLDA),ethylenediaminetetraacetic acid (EDTA), methylglycinediacetic acid(MGDA), hydroxy ethylethylenediaminetetraacetic acid (HEDTA), ordiethylenetriaminepentaacetic acid (DTPA). The carboxylic acid systemcan include a single carboxylic acid system, a di-carboxylic acidsystem, a tri-carboxylic acid system, or a tetra-carboxylic acid system.The acidic fluid can also include any other acid systems (for example,mineral or organic). The acidic fluid can include a mixture of two ormore of the above acid systems at different concentrations.

The acidic fluid can be also gelled by linearly polymers (for example,synthetic polymer like polyacrylamide (PAM), biopolymer like Guar,carboxymethyl hydroxypropyl guar (CHMBG) or terpolymer), gelled bycrosslinked polymer system (for example, synthetic like PAM, biopolymerlike CHMBG, or terpolymer), gelled by viscoelastic surfactant (VES)system, emulsified by diesel or oil (for example, at differentqualities), or foamed by a particular gas such as nitrogen (N₂), carbondioxide (CO₂), air, methane, or natural gas. In a particular example,the emulsified acid includes 30 vol % diesel and 70 vol % HCl solutions.

As the acidic fluid is reactive with the formation, a diversion fluid (adiverter or a diversion agent) can be added to the acidic fluid tominimize fluid leakoff inside the formation and keep the acid reactionwith fracture faces. Particularly, the diversion fluid can be used inhigh permeability and naturally fractured carbonate formations, wherelong etched fractures are difficult to obtain. Diversion can be obtainedby gelling the acid using crosslinking and polymer, or using asurfactant based material. A crosslinked non-reactive fluid can be alsoused as the diversion fluid. In a particular example, the diversionfluid includes encapsulated weak organic acids with an acidconcentration of 15.0% or viscoelastic surfactants (VES).

A gas is introduced into the wellbore to foam fluids in the wellbore(206). The gas can be introduced throughout the treatment, for example,after the creation of the formation fracture and until completion of thetreatment.

In some implementations, introducing the gas into the wellbore includesinjecting or pumping the gas continuously (for example, from a cryogeniccylinder from a wellhead) into the wellbore. The gas can be injectedunder a treating (or treatment) pressure, as illustrated in FIG. 4B. Insome implementations, the gas is pulsed into the fluids, for examples,as multiple bubbles or gas slugs.

In some implementations, introducing the gas into the wellbore includesgenerating the gas in-situ in the fluids in the wellbore. For example,nitrogen gas can be generated by chemical reaction between aqueoussolutions of nitrogen salts, such as reacting zinc metal with HCl oraluminum with NaOH solution.

A foam quality of the fluids is increased with time during the treatment(408). The foam quality can be based on a volume of the introduced gasand a total volume of the fluids in the wellbore. In some examples, thefoam quality (Fm) is defined as a ratio between a volume Vg of gas in adispersed phase and a total foam volume Vt, as follows:

Fm=Vg/Vt=Vg/(Vg+Vl),

where the total foam volume Vt represents the aggregate volume of thegas and liquid which form the foams and Vl represents a volume of theliquids for forming the foams. In some cases, Vg can be a total volumeof the introduced gas. In some cases, Vl can be a total volume of thefluids injected in the wellbore, including the pad fluid, the acidfluid, the diverter, and the flushing fluid. The foam quality can bealso noted as a Mitchell foam quality.

The foam quality can be further corrected with a wellhead pressure, adownhole (or bottomhole) pressure, and/or temperature modelling inreal-time accordingly. In some cases, during the treatment, at leastthree types of foam qualities can be monitored, including a wellheadfoam quality, a predicted downhole (or bottomhole) foam quality, and acalculated real-time actual downhole foam quality. A corrected foamquality can be determined based on the foam qualities. The foam qualitycan be monitored, measured, and adjusted. In some cases, the foamquality can be determined empirically. In some cases, a foam loop testcan be performed to identify the foam quality and adjust it accordingly.

During the treatment, the foam quality can be controlled to increasewith time, for example, from 0 to 80%. The process 200 can includemonitoring reaction of the fracture to the acidic fluid during thetreatment, and controlling the foam quality based on the monitoredreaction, for example, by adjusting at least one of an injection rate ofthe acidic fluid, an injection volume of the acidic fluid, anintroduction rate of the gas, or an introduction volume of the gas. Thefoam quality can be also controlled by adjusting at least one of aninjection rate of the pad fluid, an injection volume of the pad fluid,an injection rate of the diversion fluid, or an injection volume of thediversion fluid. In some examples, the reaction of the fracture can bemonitored in real time by monitoring a treating pressure, a wellheadpressure, a bottomhole (or downhole) pressure, a bottomhole internalphase, a liquid (or fluid) pumping rate, a gas pumping rate, or a slurryrate, as illustrated in FIGS. 4A-4B. For example, a sharp substantialpressure drop of the treating pressure at constant or increasing liquidpumping rate after formation breakdown can indirectly indicate highleakoff in the formation.

The process 200 can include alternately performing steps of injectingthe fracturing pad fluid, the acidic fluid, and the diversion fluid inany suitable order, while keeping introducing the gas during the steps.The injection rate of the introduced gas for a current step can be nosmaller than (larger than or identical to) an injection rate of theintroduced gas for a previous step. In some cases, a volume of theintroduced gas for a current step can be no smaller than (larger than oridentical to) a volume of the introduced gas for a previous step. Insome cases, a volume of the introduced gas for a current step can besmaller than a volume of the introduced gas for a previous step.

In some cases, during the treatment, the introduction rate of the gas iskept increasing with time, for example, from 4,000 standard cubic feetper minute (scf/min or scfm) to 8,000 scf/min. The introduction volumeof the N₂ gases in each step of the treatment can vary within a range,for example, from 44 Gallons to 2330 Gallons. In any cases, the foamquality is controlled to increase with time during the steps.

The injection rate of the acidic fluid can be reduced (or decreased)with time during the treatment, which can lead to achieve fractureclosure during a main acid treatment and a majority of the acid can beconsumed while the fracture is closed. Injecting the acidic fluid caninclude injecting the acidic fluid at a pressure lower than a fractureclosure pressure that is capable of causing a closure of the formationfracture. In some cases, the injection rate of the acidic fluid can bekept constant with time during the treatment. In some cases, theinjection rate of the acidic fluid can be also increased with timeduring the treatment.

The process 200 can include cleaning the wellbore after closure of theformation fracture, for example, by flowing a flushing fluid. Theflushing fluid can include no acid, such as treated water. The treatmentcan include an overflush step and a final flush step. During theoverflush step, a larger volume of the flushing fluid can be displaceddeeper into a reservoir. During the final flush step, a smaller volumeof the flushing fluid is mainly displaced within the wellbore. The gascan be kept introduced into the wellbore during the cleaning thewellbore.

FIG. 3 shows another example process 300 of an acid fracture treatmentwith an acidic retardation system. The acidic retard system can includean acidic retard agent configured to reduce the reactivity of the acidicfluid. In some examples, the acidic retard agent includes a gas with lowdensity and low viscosity such as nitrogen (N₂), carbon dioxide (CO₂),air, methane, or natural gas. In some examples, the acidic retard agentincludes at least one of linearly polymer (for example, syntheticpolymer like PAM, biopolymer like CHMBG, or terpolymer), crosslinkedpolymer system (for example, synthetic polymer like PAM, biopolymer likeCHMBG, or terpolymer), viscoelastic surfactant (VES) system, or dieselor oil. The acidic fluid can be gelled by the acidic retard agent suchas the linearly polymer, crosslinked polymer system, or the VES system.The acidic fluid can be emulsified by diesel or oil, for example, atdifferent qualities.

Fracturing of a subterranean formation in which a wellbore is formed isinitiated to create a formation fracture (302). After initiating thefracturing for a period of time, an acidic fluid is injected into thewellbore to etch walls of the formation fracture to thereby createfracture conductivity (304). Steps 302 and 304 are similar to steps 202and 204 of FIG. 2, respectively.

The acidic retard system is introduced into the wellbore to reducereactivity of the acidic fluid in the wellbore (306). The acidic retardsystem can be introduced throughout the treatment, for example, afterthe creation of the formation fracture and until completion of thetreatment.

Reaction of the fracture to the acidic fluid and the acidic retardsystem is monitored during the treatment (308), and a foam quality offluids in the wellbore is controlled based on the monitored reaction(310). The foam quality is based on the introduced acidic retard system.The acid retard system can include viscosified acid, emulsified acid, oran acid system in the diverter stage. Different acidic retard systemscan form different foam qualities. For example, emulsified acid systemsthat are diesel based tend to destabilize foams comparative toviscosified acid systems. With a particular acidic retard system, acorresponding foam quality can be determined and controlled.

Controlling the foam quality of the fluids in the wellbore can includeincreasing the foam quality with time during the treatment, for example,by adjusting at least one of an injection rate of the acidic fluid, aninjection volume of the acidic fluid, an introduction rate of the acidicretard system, an introduction volume of the acidic retard system, or anintroduction concentration of an acidic retard agent in the acidicretard system. For example, the concentration of the acidic retard agentcan be changed with time to increase the retardation.

The acid fracture treatment with foaming by gases (or acidic retardationsystem) as described herein can reduce a total required acid volume, forexample, from an acid volume 1200-1250 gals/ft. to 500-700 gals/ft.Foaming can lead to better acid retardation to achieve deeper acidpenetration, an increase of acid diversion efficiency, a reduction of aleak-off rate, and improved solids transport (for example, for soliddiverter), which enables to get a higher apparent viscosity. The acidfracture treatment can also achieve better clean-up, because gas such asnitrogen can reduce the overall acid density to allow natural flow backfor depleted reservoirs (without a need for any additional gas liftingtechnique, precipitates can be lifted with flowback, and gas liftingafter the treatment can be eliminated. Wells treated with the gasfoaming shows a faster clean-up after treatment compared to wellstreated without gas foaming. The acid fracture treatment can also reduceformation damage, minimize well shut-in time as there is no need to haveclosed fracture acidizing (CFA) treatment, and achieve bettercontrol/uniform acid coverage. The acid fracture treatment can achievelower bottomhole treatment pressures, higher post acid fractureproductivity and thus production rates, reduced site time, saved costson gas lifting operations with coiled tubing, and saved fresh waterrequired per treatment. The acid fracture treatment can also achievebetter reservoir coverage due to better diversion, deeper acidpenetration, less hydraulic horse power and surface lines required.

Examples of Acid Fracture Treatments

TABLE 1 an acid fracture treatment without gas foaming Pump Rate StepFluid Volume Acid Conc. Step Name (bbl/min) Fluid Name (gal) (%) PAD 120.0 DBXF 3500 0.0 Acid 1 20.0 Emulsified acid 4000 28.0 PAD 2 25.0 DBXF1500 0.0 Diverter 1 25.0 Particulates 1500 15.0 PAD 3 30.0 DBXF 3500 0.0Acid 2 30.0 HCl 4500 28.0 PAD 4 35.0 DBXF 1500 0.0 Diverter 2 35.0Particulates 1500 15.0 PAD 5 36.0 DBXF 4000 0.0 Acid 3 36.0 HCl 550028.0 PAD 6 40.0 DBXF 1500 0.0 Diverter 3 40.0 Particulates 2000 15.0 PAD7 45.0 DBXF 5000 0.0 Acid 4 45.0 HCl 6500 28.0 Overflush 20.0 Water10000 0.0 Flush 20.0 Water 6800 0.0

Table 1 shows steps of an example acid fracture treatment without gasfoaming.

A fracturing pad fluid was first injected into a wellbore to break downa formation penetrated by the wellbore. The pad fluid was a water-basedpad, for example, a gelled water or crosslinked gel fluid such asdelayed borate xlinked fluid (DBXF). The pad fluid delayed boratexlinked fluid was pumped at a rate of 20.0 barrel per minute (bbl/min)and the total fluid volume in step PAD 1 was about 3500 Gallons (gals).The pad fluid was pumped into the wellbore to create a fracture with adesired height, width, length, or any suitable combination therefrom.For example, the created fracture can have a volume that is around10-20% of a total pumped volume of the pad fluid.

Once the desired values of created fracture dimensions were achieved, anacid fluid was injected into the wellbore to etch walls of the fractureto create fracture conductivity. The acid fluid includes emulsified withan acid concentration of 28.0 wt. %.

A diverter (a diversion fluid or a diversion agent) was added to theacid fluid to minimize fluid leakoff inside the formation and keep theacid reaction with fracture faces. The diverter may include particulateswith an acid concentration of 15.0%.

The pad fluid, the acid fluid, and the diverter were alternatelyinjected into the wellbore, as illustrated in Table 1. The acid fracturetreatment includes a number of sequential steps: PAD 1, Acid 1, PAD 2,Diverter 1, PAD 3, Acid 2, PAD 4, Diverter 2, PAD 5, Acid 3, PAD 6,Diverter 3, PAD7, and Acid 4. Each of the pad fluids, the acid fluids,and the diverters was varied the pump (or injection) rate and the stepfluid volume (that is, a fluid volume pumped in a step). For example,the pump rate of the pad fluid was increasing with time during thetreatment, while the step fluid volume of the pad fluid was changed fordifferent steps, within a range from 1,500 Gallons to 5,000 Gallons.

In the acid fracture treatment of Table 1, the acid fluid during themain acid stages (for examples, steps Acid 1, Acid 2, and Acid 3) wasinjected (or pumped) at a pressure higher than a fracture closurepressure that can lead to a closure of the fracture, and the acidreacted with the fracture face at open conditions. To keep the pressureconstant, as illustrated in Table 1, the injection rate (or the pumprate) of the acid fluid was kept increasing with time, for example, from20.0 bbl/min to 45.0 bbl/min. The step fluid volume of the acid fluidwas also kept increasing with time, for example, from 4,000 Gallons to6,500 Gallons. The pump rate of the diverter was also kept increasingwith time to provide sufficient diversion for the increased acid fluid,for example, from 25.0 bbl/min to 40.0 bbl/min. The step fluid volume ofthe diverter was also increased from 1,500 Gallons to 2000 Gallons.

At a closed-fracture acid step (Acid 4), 28.0 wt % hydrochloric (HCl)acid was pumped below the fracture closure pressure. Then, the wellboreand the fracture was cleaned by flushing fluid, for example, water. Thetreatment includes an overflush step and a final flush step.

In the wellbore, the injected (or pumped) acid volumes varied from 1,500to 2,000 gal/ft. After long-term production and the usage of emulsifiedacids, in-situ-gelled acids, formic acid/HCl, or viscoelastic acids, theacid volumes were reduced to 450 gals/ft.

FIG. 4A shows an example time diagram 400 of the acid fracture treatmentof Table 1. Curve 402 shows a treating pressure applied during injectingthe fluids (for example, the pad fluid, the acid fluid, the diverter,and the flushing fluid) into the wellbore. Curve 404 shows a slurry ratein the wellbore. Curve 406 shows a bottomhole (BH) pressure Curve 408shows an annulus pressure. The X axis shows the time, the left Y axis isfor the treating pressure (pound per square inch, psi), and the right Yaxis is for the slurry rate (bbl/min).

Table 2 shows steps of an example acid fracture treatment with gasfoaming.

TABLE 2 an acid fracture treatment with gas foaming Rate Volume N₂ RateN₂ Volume Foam Quality Step Name (bbl/min) Fluid Name (gal) (scf/min)(gal) (%) Cool Down 10 Treated Water 500 0 0 0 Spearhead 15 26% HCl 30000 0 0 PAD 1 25 Xlinked gel 1500 0 0 0 Acid 1 30 26% HCl 4500 0 0 0 PAD 235 Xlinked gel 1500 4000 44 5 Diverter 1 20 VES 1500 4000 77 10 PAD 3 15Xlinked gel 1800 4000 123 15 Acid 2 15 26% HCl 5500 5500 516 20 PAD 4 20Xlinked gel 1500 6500 125 25 Diverter 2 15 VES 2000 6500 222 30 PAD 5 12Xlinked gel 1800 6500 250 35 Acid 3 10 26% HCl 6000 6500 998 39 PAD 6 8Xlinked gel 1500 6500 312 45 Diverter 3 7 VES 2000 6500 475 49 PAD 7 5Xlinked gel 1800 6500 599 60 Acid 4 5 26% HCl 7000 6500 2330 65Overflush 5 Treated Water 2500 7000 896 70 Flush 5 Treated Water 35008000 1434 78

The wellbore was first cooled down with treated water. Then an initialfracturing fluid was provided to initial penetration into the formationduring a spearhead step. The initial fluid includes an acid with arelatively low viscosity, for example, 26% HCl.

Then, a fracturing pad fluid, for example, a gelled water or crosslinkedgel fluid such as xlinked gel, was injected into the wellbore to breakdown the formation to initiate a fracture. Once desired values of thecreated fracture dimensions were achieved, an acid fluid, for example,26% HCl, was pumped into the wellbore to etch walls of the fracture tocreate fracture conductivity. Also a diverter (or diversion fluid), forexample, viscoelastic surfactants (VES), was also added to the acidfluid to minimize fluid leakoff inside the formation and keep the acidreaction with fracture faces.

Similar to the acid fracture treatment of Table 1, the pad fluid, theacid fluid, and the diverter were alternately injected into the wellborein any suitable order. As illustrated in Table 2, the acid fracturetreatment includes a number of sequential steps: PAD 1, Acid 1, PAD 2,Diverter 1, PAD 3, Acid 2, PAD 4, Diverter 2, PAD 5, Acid 3, PAD 6,Diverter 3, PAD7, Acid 4, Overflush, and Flush.

One of the differences between the treatment of Table 2 and thetreatment of Table 1 is that a gas (for example, nitrogen N₂) wasintroduced for foaming the fluids in the early stages of the treatmentuntil the end of the treatment, for example, from step PAD 2 to stepFlush.

During the treatment, the foam quality was controlled to increase withtime, for example, from 0 to 78%, as illustrated in Table 2. Reaction ofthe fracture in the wellbore was monitored to the acid fluid during thetreatment, and the increase of the foam quality was controlled based onthe monitored reaction, for example, by adjusting at least one of theintroduction rate of the gases, the introduction volume of the gases,the injection rate of the acid fluid, or the injection volume of theacid fluid.

As illustrated in Table 2, during the treatment, the introduction rateof the N2 gases was increased from 4,000 scf/min to 8,000 scf/min. Thestep introduction volume of the N2 gases varied within a range of 44Gallons to 2330 Gallons. The total acid injection rate was reduced withtime, which leaded to achieve fracture closure during main acidtreatment (for example, from step Acid 1 to step Acid 4). The acid fluidwas injected at a pressure lower than a fracture closure pressure. Theinjection rate of the acid fluid was reduced from 30 bbl/min to 5bbl/min. Therefore, a majority of the acid was consumed while thefracture was closed.

FIG. 4B shows an example time diagram 450 of the acid fracture treatmentof Table 2. Curve 452 shows a treating pressure (applied duringinjecting the fluids (for example, the pad fluid, the acid fluid, thediverter, and the flushing fluid) and gases into the wellbore. Curve 454shows a slurry rate in the wellbore. Curve 456 shows a predicted BHInternal Phase, where curve 458 shows a BH Internal Phase and curve 460shows a calculated BH pressure. Curve 462 shows N₂ standard injectionrate. Curve 464 shows a wellhead Internal Phase, and curve 466 shows awellhead rate. The X axis shows the treatment time, the left A axis canbe used as pressure values (pounds per square inch gauge, psig) for thetreating pressure and the calculated BH pressure or as injection rates(standard cubic feet per minute, scfm) for N₂ standard rate. The right Baxis can be used as fluidic flowing rates (barrels per minute, bpm) forthe slurry rate and the wellhead rate. The right G axis is used aspercentages (%) for the predicted BH Internal Phase, the BH InternalPhase, and the wellhead Internal Phase.

During the treatment, a wellhead foam quality can be calculated based onactual wellhead pressure and temperature (refereed as a wellheadInternal Phase). BH Internal Phase was calculated based on calculated BHpressure and temperature in real time, and an actual BH foam quality canbe calculated based on the calculated BH Internal Phase. Predicted BHInternal Phase was calculated in real time, which can be used to predicta bottomhole foam quality. The foam quality can be predicted andcontrolled dynamically based on the calculated wellhead foam quality,the calculated actual bottomhole foam quality, and the predictedbottomhole foam quality.

Table 3 shows a comparison between two wells (Wells # A &B) usingdifferent technologies. Well # A was treated using the acid fracturetreatment without gas foaming, similar to that of Table 1, while well #B was treated using the acid fracture treatment with gas foaming,similar to that of FIG. 2, and Table 2. Wells # A and B were located inthe same area with substantially identical parameters:

-   (i) net pad thickness of 55 ft. for both wells,-   (ii) average open hole section per stage: 942 ft. for well # A and    918 ft. for well # B ft.,-   (iii) reservoir porosity around 5% for both wells.

TABLE 3 Comparison of wells# A&B under different treatments Well No. A BTechnology Acid fracture Acid fracture Treatment without treatment withgas foaming gas foaming Acid Volume per stage (gals) 23,688 25,795Diverter volume per stage (gals) 7,454 3,862 Total N₂ Acid Frac. perstage (gals) 0 6,925 Total N₂ to lift post Acid Frac. (gals) 6,000 0Production Post Acid Frac. 0.0 18.7 (MNISCFD) FWHP Post Acid Frac. (psi)0 2,316 Reservoir pressure (psi) 3,850 3,320

Based on data shown in Table 3, for well # A treated with the acidfracture treatment without gas foaming, 23,688 gals of reactive acidsystem and 7,454 gals of diverter system were injected, followed by 6000gals of N₂ as gas lifting method to reduce the hydrostatic pressure fora better flow back. However, gas production after the treatment was zero(that is, well considered dead), as the treatment fluid killed the welland gas lifting was not able to initiate the production.

In comparison, for well # B treated with the acid fracture treatmentwith gas foaming, 25,795 gals of reactive acid system and 3,862 gals ofdiverter system were injected with 6,925 gals of N₂ for foaming purpose(not as gas lifting technique where gas is pumped after the treatment).Post-fracture production data shows that Well B produced an 18.7 Millionstandard cubic feet per day (MMSCFD) with a wellhead pressure of 2,316psi. Well B followed back naturally after the treatment without the needof any additional gas lifting technique. The reservoir pressure for well# B (3,320 psi) is lower than well # A (3,850) by about 500 psi. Thisshows the treatment with gas foaming can enhance the well productivitycompared to the treatment without gas foaming.

Table 4 shows another comparison between two wells (wells # C & D) usingdifferent technologies. Well # C was treated using the acid fracturetreatment similar to that of Table 1 except that, at the end of thetreatment, N₂ was pumped for foaming, while well # D was treated usingthe acid fracture treatment with gas foaming, similar to that of FIG. 2or Table 2. Wells # C and D were located in the same area withsubstantially identical parameters:

-   (i) net pad thickness of 55 ft. for both wells,-   (ii) average open hole section per stage: 724 ft. for well # C and    652 ft. for well # D,-   (iii) reservoir porosity around 8.5% for well # C and 5% for well #    vD.

TABLE 4 Comparison of wells# C&D under different treatments Well No. C DTechnology Acid fracture Acid fracture treatment with N₂ treatment withN₂ foaming at the end foaming throughout of the treatment the treatmentAcid Volume per stage, gals 29,569 24,445 Diverter volume per stage,gals 7,622 4,073 Total N₂ Acid Frac. per stage, 2,274 7,450 gals TotalN₂ to lift post Acid Frac., 0 0 gals Production Post Acid Frac., 5.015.6 MMSCFD FWHP Post Acid Frac., psi 1,530 2,997 Reservoir pressure,psi 5,156 4,150

Based on data shown in Table 4, for well # C, a 29,569 gals of reactiveacid system and 7,622 gals of diverter system were injected with a 2,274gals of N₂ as foaming fluid at the end of the treatment similar to thetreatment of FIG. 2 and Table 2. Well # C was able to naturally produceafter the treatment with a 5 MIVISCFD with a wellhead pressure of 1,530psi.

In comparison, for well # D, 24,445 gals of reactive acid system and4,073 gals of diverter system were injected with 7,450 gals of N2 forfoaming purpose (not as gas lifting technique that is pumped after thetreatment). Well # D produced a 15.6 MIVISCFD with a wellhead pressureof 2,997 psi. Well # D followed back naturally after the treatmentwithout the need of any additional gas lifting technique. Also thereservoir pressure for well # D (4150 psi) is lower than well # C (5156)by almost 1,000 psi. This shows that the acid fracture treatment withgas foaming can enhance the productivity of the well compared to thetreatment without gas foaming.

The earlier provided description of example implementations does notdefine or constrain this specification. Other changes, substitutions,and alterations are also possible without departing from the spirit andscope of this specification. Accordingly, other embodiments are withinthe scope of the following claims.

1. A method of acid fracture treatment, comprising: initiatingfracturing of a subterranean formation in which a wellbore is formed tocreate a formation fracture by flowing a fracturing pad fluid into thewellbore to break down the formation to thereby create the formationfracture; after initiating the fracturing for a period of time,injecting an acidic fluid into the wellbore to etch walls of theformation fracture to thereby create fracture conductivity; introducinga gas into the wellbore to foam fluids in the wellbore; increasing afoam quality of the fluids with time during the treatment, wherein thefoam quality is based on a volume of the introduced gas and a volume ofthe fluids in the wellbore; and alternately performing steps ofinjecting the fracturing pad fluid and the acidic fluid, while keepingintroducing the gas during the steps.
 2. The method of claim 1, furthercomprising: monitoring reaction of the fracture to the acidic fluidduring the treatment; and controlling the increasing of the foam qualitybased on the monitored reaction by adjusting at least one of aninjection rate of the acidic fluid, an injection volume of the acidicfluid, an introduction rate of the gas, or an introduction volume of thegas.
 3. The method of claim 2, wherein monitoring reaction of thefracture comprises: monitoring at least one of parameters including atreating pressure, a wellhead pressure, a bottomhole pressure, a fluidpumping rate, a gas pumping rate, and a slurry rate; and determining thereaction of the fracture based on the monitored parameters.
 4. Themethod of claim 1, further comprising: calculating the foam qualitybased on the volume of the introduced gas and the volume of the fluidsin the wellbore; and correcting the calculated foam quality with atleast one of a calculated wellhead foam quality, a predicted bottomholefoam quality, or a calculated actual bottomhole foam quality.
 5. Themethod of claim 4, further comprising: calculating the calculatedwellhead foam quality based on an actual wellhead pressure and atemperature; predicting the predicted bottomhole foam quality based on apredicted bottomhole internal phase; and calculating the calculatedactual bottomhole foam quality based on a calculated bottomhole internalphase that is calculated based on a bottomhole pressure and thetemperature.
 6. The method of claim 1, further comprising: determiningthat a dimension of the created formation fracture reaches a value, andin response, injecting the acidic fluid into the wellbore.
 7. The methodof claim 1, wherein introducing the gas comprises: introducing the gasafter the creation of the formation fracture and until completion of thetreatment.
 8. The method of claim 1, further comprising: decreasing aninjection rate of the acidic fluid with time during the treatment. 9.The method of claim 1, wherein injecting the acidic fluid comprises:injecting the acidic fluid at a pressure lower than a fracture closurepressure that is capable of causing a closure of the formation fracture.10. The method of claim 9, wherein injecting the acidic fluid comprises:keeping an injection rate of the acidic fluid constant with time duringthe treatment.
 11. The method of claim 9, wherein injecting the acidicfluid comprises: increasing an injection rate of the acidic fluid withtime during the treatment.
 12. The method of claim 1, wherein a volumeof the introduced gas for a current step is no smaller than a volume ofthe introduced gas for a previous step.
 13. The method of claim 1,wherein a volume of the introduced gas for a current step is smallerthan a volume of the introduced gas for a previous step.
 14. The methodof claim 1, wherein an injection rate of the introduced gas for acurrent step is no smaller than an injection rate of the introduced gasfor a previous step.
 15. The method of claim 1, wherein the fracturingpad fluid comprises at least one of a gelled water or a crosslinked gelfluid.
 16. The method of claim 1, wherein introducing a gas into thewellbore comprises: generating the gas in-situ in the fluids in thewellbore.
 17. The method of claim 1, wherein the acidic fluid isconfigured to dissolve the formation and comprises at least one of:hydrochloric (HCl) acid with a concentration from 0.1 to 32 wt. %,formic acid with a concentration from 0.1 to 12 wt. %, acetic acid witha concentration from 0.1 to 20 wt. %, methaneseleninic (MSA) acid with aconcentration from 0.1 to 92 wt. %, chelating agent with a concentrationfrom 0.1 to 40 wt. %, or a carboxylic acid system.
 18. The method ofclaim 1, wherein the acidic fluid is configured to be gelled by linearlypolymers, gelled by crosslinked polymer system, gelled by viscoelasticsurfactant (VES) system, emulsified by diesel or oil, or foamed by aparticular gas.
 19. The method of claim 1, wherein the introduced gashas low density and low viscosity and comprises at least one of:nitrogen (N₂), carbon dioxide (CO₂), air, methane, or natural gas. 20.The method of claim 1, further comprising: adding a diversion fluid tothe acidic fluid, wherein the diversion fluid comprises at least one ofa crosslinking polymer, a surfactant based material, or a crosslinkednon-reactive fluid.
 21. The method of claim 1, further comprising:cleaning the wellbore after closure of the formation fracture.